Method and apparatus for achieving power augmentation in gas turbines using wet compression

ABSTRACT

A gas turbine unit and method of operation thereof are disclosed. A very quick and easily controllable augmentation or reduction of shaft power produced by the gas turbine unit, in particular of large gas turbine units exhibiting a pressure ratio larger than 15 bar, is achieved by providing at least one liquid droplet injection device on the upstream side of the compressor for injecting liquid into the stream of intake air. The injection device allows the addition of liquid mass flow in the form of liquid droplets corresponding to the desired increase of shaft power. The amount of water mass flow corresponding to the desired increase or decrease of shaft power output is added or reduced in a substantially stepless manner immediately within a time interval determined by design characteristics of the injection device. Water mass flow is preferentially injected substantially across the entire cross-section of the intake air guide.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of the U.S. National Stagedesignation of co-pending International Patent ApplicationPCT/CH02/00663 filed Dec. 4, 2002, the entire content of which isexpressly incorporated herein by reference thereto.

FIELD OF THE INVENTION

The present invention relates to a gas turbine unit as well as to amethod of operating a gas turbine unit both using over-fogging. Moreparticularly it concerns a gas turbine unit essentially comprising: acompressor for compressing intake air supplied thereto and dischargingthe compressed air; a combustion chamber in which fuel is combusted withthe compressed air discharged from said compressor; a turbine driven bythe hot combustion air discharged from said combustion chamber.

BACKGROUND OF THE INVENTION

It is well known that the addition of water, or other suitable liquidsor mixtures of liquids, into the working medium of gas turbines can beused for increasing the power that can be generated by gas turbineunits. The increase of available power is due to, among other reasons,the cooling effect of the added water reducing the compressor powerconsumption and allowing an increased firing of the gas turbine unit, aswell as due to the increased mass flow passing the turbine blades.

Water can be added either in the form of vapour, that is in the form ofhumidified air or, and this relates to the present invention, in theform of small liquid droplets, i.e. water can be added above thesaturation level of water in the air. This technique, known asover-fogging, is usually carried out by adding liquid droplets ofparticular size to the air stream entering the compressor of the gasturbine unit (so-called ‘wet compression’). ‘Wet compression’ allows toincrease the power available due to the reduction of work required forcompression of the inlet air, as the latent heat for evaporation of thiswater cools the inlet air stream when it passes the compressor stages.

There are a number of documents describing particular designs of gasturbine units and methods for their operation using ‘wet compression’.For example U.S. Pat. No. 5,930,990 as well as its continuation-in-partU.S. Pat. No. 5,867,977 describe an apparatus for ‘wet compression’ aswell as a method for increasing the power available by using ‘wetcompression’. These documents concern gas turbine units, where smalldroplets of water are being added to the intake air entering thecompressor. The increase of added water is carried out in a stepwise,incremental manner, and due to problems of thermal non-equilibriuminduced in the components of the gas turbine unit downstream of theinjection (thermal shock leading to cracking in certain alloyedcomponents and to undesired reduction of clearance between parts whichare in motion relative to each other during operation), this stepwiseaddition of water is proposed to be carried out on a timescale of 10-20minutes. Additionally the proposed means for adding the water aredesigned like a grid of nozzles lying in one plane and being arrangedsubstantially perpendicular to the direction of flow of the intake airstream. This stepwise increase of water added to the intake air can,according to this document, be achieved by either increasingly feedingthe nozzles with water or by systematically feeding more and morenozzles with water (sequential increase in time or in position).

In order to control and to optimize the addition of water when using wetcompression, WO 00/50739 proposes a particular apparatus for monitoringdestructive ‘wet compression’ power augmentation-related casingdistortions in gas turbine units. Also this document points out that inorder to avoid thermal stress when activating ‘wet compression’, theaddition of water has to be carried out smoothly under a carefulmonitoring of the associated distortions of the casing and othercomponents of the gas turbine unit.

Another particular device to be used for ‘wet compression’ is proposedin U.S. Pat. No. 6,216,443. The water is added by means of a liquiddroplet injection device provided on the upstream side of a compressor,and on the downstream side of a silencer. The addition of water iscontrolled by means of a valve, and it is also pointed out that due tothermal stress and due to the fact that concomitantly other parametershave to be adjusted when adding water to the intake air (for example theaddition of fuel has to be adjusted), the addition has to be performedsufficiently slowly.

SUMMARY OF THE INVENTION

The present invention therefore relates to providing a gas turbine unitas well as a method for its operation allowing a simple andconstructively easy augmentation of the available shaft power of the gasturbine unit by using over-fogging, i.e. by injecting liquid dropletsinto the stream of intake air upstream of the compressor. Moreparticularly, this aim shall be achieved for a gas turbine unit,essentially comprising: a compressor for compressing intake air suppliedthereto and discharging the compressed air; a combustion chamber inwhich fuel is combusted with the compressed air discharged from saidcompressor; a turbine driven by the hot combustion air discharged fromsaid combustion chamber.

More particularly, the invention relates to gas turbine units, thecompressor of which is working with a pressure ratio larger than 15 bar(i.e. the process is aiming mainly at, but not limited to large gasturbine units, and preferentially, the pressure ratio is even largerthan 20 bar), by providing at least one liquid droplet injection deviceon the upstream side of said compressor for injecting liquid into thestream of intake air in order to increase the shaft power generated bythe gas turbine unit, wherein the amount of liquid mass flowcorresponding to the desired increase or decrease of shaft power outputof the gas turbine unit is added or reduced in the form of liquiddroplets immediately, i.e. within a time interval that is determined bythe design characteristics of the liquid droplet injection device toincrease or decrease the liquid droplet mass flow, and in asubstantially stepless manner, and wherein preferentially said liquidmass flow is injected substantially across the entire cross-section ofthe air intake.

The liquid injected preferentially consists substantially or completelyof water. The water may be demineralized to avoid detrimental formationof deposit and scale, and/or may contain additives in particular toprevent the formation of deposit. For simplicity and clarity, in thefollowing the term water shall be used meaning generally liquid, whichleads to the desired effect when injected upstream of the compressor.

When talking about “immediately, i.e. within a time interval that isdetermined by the design characteristics of the liquid droplet injectiondevice”, that “immediately” means substantially as quickly as possiblewithin the bounds predetermined by the design (tube widths, control andvalve speed etc.) of the injection device. The term “immediately” or“immediate” shall in the following stand in the above sense.

Contrary to all expectations of the person skilled in the art andcontrary to all statements found in the state of the art, an immediateand stepless addition or reduction of water mass flow when usingover-fogging is possible without the deleterious effects mentioned inthe above cited documents. Surprisingly, immediate and completeswitching-on or switching-off of the liquid droplet injection device ispossible without waiting for steady state conditions in the gas turbineby using slowly increasing or decreasing amounts of water. If it isadditionally preferentially made sure that the droplets are added to thestream of intake air substantially across the entire cross-section ofthe intake air guide, the switching-on and switching-off can basicallybe carried out in an on/off-manner. This unexpectedly possible fast andsimple switching leads to a number of possible constructionalsimplifications and other advantages. On the one hand no complicatedcontrol and regulation means need to be provided for the liquid dropletinjection device, and a simple on/off-control is sufficient therebyreducing costs as well as possible sources of failure. On the other handthe shaft power-augmentation/reduction effect of the gas turbine unit isavailable much more quickly than when using some particular, slow(stepwise) slope for increasing or decreasing the water addition.

According to a first preferred embodiment of the present invention, thegas turbine unit additionally comprises a cooling system which usescompressed or partially compressed air discharged from the compressorfor cooling components of the gas turbine unit, wherein the coolingsystem comprises a cooling unit that is controlled such as to ensuresubstantially constant quality of the cooled cooling air. Coolingsystems for gas turbine units are highly sophisticated systems that haveto be carefully controlled. Any change in the mode of operation of thegas turbine leads to a consequential change of the conditions within thecompressor and to a corresponding change of the air entering the coolingsystem. To avoid flow-back of the cooling medium and to assure effectiveand sufficient cooling of the components that are being cooled by thecooling system, the cooling system is usually controlled with respect totemperature as well as pressure. Using conventional ‘wet compression’start-up schemes, the cooling system has to be heavily controlled andactively guided. In particular, the cooling unit has to be controlled inreaction to the slow (stepwise) increase of water addition in order tokeep pressure and temperature of the cooling medium downstream of thecooling unit at the desired levels i.e. within the desired limits.Surprisingly, the simplified immediate and stepless addition orreduction of water for ‘wet compression’ as proposed according to thepresent invention also considerably simplifies the control of thecooling system. The control of the cooling system can basically bereduced to a single feed forward signal synchronized to theon/off-control of the liquid droplet injection device (if need be thesignals of the two systems can be slightly displaced relative to eachother in order to take account of hysteresis-effects of the gas turbineunit). In other words it is possible to design the gas turbine unit suchthat the at least one injection device can be controlled in anon/off-manner only, and that preferably the cooling unit can becontrolled with a single signal. It is however also possible to havecertain discrete levels of desired power augmentation or reduction ofthe gas turbine unit and to have on/off-possibilities corresponding tothese levels for the two systems only.

As the single feed forward signal for the cooler is necessary anyway forthe case of an emergency shut down of the injection system, the proposedgas turbine unit clearly is a simplification of the turbine controlsystem thus increasing reliability and reducing the occurrence ofpossible errors.

According to another preferred embodiment of the present invention, thegas turbine unit comprises a fuel (gas or oil) control valve thatadjusts the fuel mass flow in order to maintain the desired firingtemperatures of the gas turbine unit. The fuel control valve is subjectto a complicated control mechanism of the gas turbine unit controlsystem, its actual position depending on numerous parameters, forexample, but not limited to the compressor discharge conditions.Accordingly, to prevent over-firing of the gas turbine unit withsubsequent deleterious effects on the combustion chamber and turbineblade components, the fuel control valve needs to be heavily controlledand actively guided, if water is added in a slow, stepwise manner, sincein reaction to such addition of liquid water droplets results in asignificant change of the compressor discharge temperature. In thisregard it shall be mentioned that over-firing of the gas turbine unitmay not only occur when decreasing the liquid injection mass flow,resulting in an increase of the compressor discharge temperature, butalso when increasing the liquid injection mass flow, resulting in adecrease of the compressor discharge temperature, due to overshootingeffects of the fuel valve control system. The present invention allowsto reduce the control interventions of the existing control of the fuelvalve using one simple feed forward signal.

According to a further preferred embodiment of the present invention,the gas turbine unit additionally comprises the ability to rapidlyincrease the power output of the unit using the immediate and steplessaddition or reduction of liquid mass flow. This is particularlyapplicable, but not limited to the case of the power generated by thegas turbine unit being converted into electricity with a generator andbeing fed into an electricity grid of electricity generators andconsumers. When the electricity grid is subject to a fast increase ordecrease in power demand caused by e.g. switching on or off of largeconsumers or a fast decrease in power generation capacity caused by e.g.the emergency shut-down of a large power generation unit, the frequencyof the electricity grid drops or rises and an immediate increase ordecrease in power generation capacity within seconds or a few minutes isneeded in order to maintain the electricity grid frequency reasonablystable and to prevent breakdown of parts of or even of the completeelectricity grid. The ability of a particular gas turbine unit torapidly increase or decrease the power output in a situation of low orhigh electricity grid frequency is also known as its ability to beoperated in ‘frequency response’ mode. The current invention providesmeans to rapidly, i.e. on a seconds time scale increase or decrease thepower output of the gas turbine unit significantly, e.g. by 10% of itsfull load capacity, by immediate and stepless addition of water massflow into the intake air stream. Even more particularly, when theelectricity grid frequency drops, also the shaft speed of the gasturbine unit is reduced by the corresponding amount, assuming the gasturbine unit comprises a single shaft arrangement, reason being that theshaft of the gas turbine unit is coupled with the shaft of theelectricity generator, and that the shaft speed of the generator issynchronized to the frequency of the electricity grid. In case of areduced shaft speed, the surge margin, which defines the limit forstable operation of the compressor of gas turbine units, tends to bereduced, limiting the ability of the gas turbine unit to increase itspower output or even forcing it to reduce its power output in order toprevent destructive compressor surge, thus worsening the generationcapacity situation of the electricity grid. The liquid injection meansaccording to the present invention substantially improves the ability ofa gas turbine unit to rapidly increase power output even in case of areduced shaft speed in that way that by immediate and stepless additionof water, the surge margin of the compressor of the gas turbine unit isincreased by cooling the compressor blade section.

According to another preferred embodiment of the present invention thegas turbine unit additionally comprises an intake manifold situatedupstream of said compressor and an intake duct situated upstream of saidintake manifold connected to said intake manifold by means of anexpansion joint, and the liquid droplet injection device is essentiallysituated at the expansion joint between the intake duct and the intakemanifold, wherein preferably the intake duct additionally comprises asilencer located upstream of said liquid droplet injection device and afilter located essentially at the intake opening of the intake duct, andwherein preferably additional cooling means for cooling the intake airare situated downstream of the filter. Locating the liquid dropletinjection device close to the or at the expansion joint proves to beparticularly advantageous, as the droplets can be evenly distributedacross the cross-section, the droplets can be generated in a very smallsize and the liquid droplet injection device can be easily installed andmaintenance is kept simple. According to still another preferredembodiment, the liquid droplet injection device consists of a grid offogging water ducts, preferably arranged in an essentially parallelmanner on a carrying rack, on the downstream side of which fogging waterducts fogging nozzles are mounted for injecting droplets into the streamof intake air, wherein preferably the liquid droplet size injected bythe liquid droplet injection device is in the range of 2 to 40 μm,preferably around 10 μm. Preferably, the spacing of the fogging waterducts as well as the spacing of the fogging nozzles mounted on saidfogging water ducts is adapted to the flow of intake air to achieve evendroplet distribution in the stream of intake air. Preferentially thenozzles are binary nozzles fed with gas or quasi-gas and liquid.

According to yet another preferred embodiment of the present invention,the liquid droplet injection device is located even closer to thecompressor inlet, preferably at the compressor bellmouth. Thisminimization of the distance of the position of droplet injection to thecompressor inlet is advantageous, since it widely prevents secondarydroplet formation, growing size of the injected droplets due toconglomeration, water loss on the walls or other fixed equipment in theintake manifold as well as centrifugal effects due to deflection of theinlet air stream.

As concerns the cooling system, according to another preferredembodiment, the cooled cooling air is controlled to have a temperaturearound 300 and 400 degree Celsius, preferably between 330 and 380 degreeCelsius allowing a tolerance of less than +/−10 degree Celsius, whereina pressure in the range of 15 to 40 bar, preferably in the range of 20to 30 bar is maintained. Even for cooling systems with such smalltolerances, the switching on/off of the over-fogging according to thepresent invention is possible.

Further preferred embodiments of the gas turbine unit according to thepresent invention are described in the dependent claims.

Additionally, the present invention concerns a process for achieving anincrease or decrease in shaft power production from a gas turbine unit,which gas turbine unit essentially comprises: a compressor forcompressing intake air supplied thereto and discharging the compressedair; a combustion chamber in which fuel is combusted with the compressedair discharged from said compressor; a turbine driven by the hotcombustion air discharged from said combustion chamber. In accordancewith the above gas turbine unit according to the invention, said processis characterized in that said compressor is working with a pressureratio larger than 15 bar (i.e. the process is aiming mainly at, but notlimited to large gas turbine units, and preferentially the pressureratio is even 20 bar), and that by means of at least one liquid dropletinjection device provided on the upstream side of said compressor liquidis injected into the stream of intake air in order to increase the shaftpower generated by the gas turbine unit, wherein said injection iscarried out by means of an immediate and stepless addition or reductionof liquid mass flow in the form of liquid droplets corresponding to thedesired increase or decrease respectively of power of the gas turbineunit, and wherein preferentially said water mass flow is being injectedsubstantially across the entire cross-section of the intake air guide.As pointed out above, surprisingly, immediate and complete switching-onor switching-off of the liquid droplet injection device is possiblewithout waiting for steady state conditions in the gas turbine by usingslowly increasing or decreasing amounts of liquid. Provided that thedroplets are added to the stream of intake air substantially across theentire cross-section of the intake air guide, the switching-on/off caneven more easily basically be carried out in an on/off-manner.

According to the first preferred embodiment of the process according tothe present invention, the gas turbine unit additionally comprises acooling system which uses compressed or partially compressed airdischarged from the compressor for cooling components of the gas turbineunit, wherein the cooling system comprises a cooling unit which is beingcontrolled depending on the quality of the cooled cooling air. Coolingsystems of large gas turbine units are highly sophisticated deviceswhich necessitate very accurate control in order to ensure that constantconditions can be maintained at the locations where the cooling mediumis used. Accordingly, if the liquid droplet injection device is switchedon using an incremental scheme, also the cooling device has to becontrolled in accordance with the incrementally changing conditions inthe compressor where the cooling air is branched off from. Preferablysaid process is being carried out using a gas turbine unit as it hasbeen described above.

According to another preferred embodiment of said process, between 0.5and 5 mass. %, preferably between 1.0 and 3.0 mass % of water areinjected into the intake air to achieve an increase of power of the gasturbine unit of e.g. up to 10%. Preferably, water is injected at apressure of up to 250 bar, preferentially between 100 to 180 bar, andeven more preferably at a pressure of around 140 bar water pressure, andthis pressure is built up immediately within 1 s and 60 s, preferablywithin in the range of 10-30 s.

For starting up of the gas turbine unit, it is proposed to in a firststep start up the gas turbine to full load, in case of additionalcooling systems to switch on these cooling systems, and to, after theexpiration of a delay of in the range of 15 to 45 minutes, preferably inthe range of 30 minutes, add water by means of the liquid dropletinjection device.

Further preferred embodiments related to the process for achieving anincrease in power production from a gas turbine unit are described inthe dependent claims.

The present invention additionally comprises uses of the above-mentionedgas turbine unit in the field of electricity generation and in the fieldof production of mechanical power generation.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention, its nature as well as its advantages, shall be describedin more detail below with the aid of the accompanying drawings.Referring to the drawings:

FIG. 1 is a schematic view of a gas turbine unit and a heat recoverysteam generator, showing the location of the liquid droplet injectiondevice as well as the possible cooling ducts;

FIGS. 2 a and 2 b are schematic views of the intake region of a gasturbine unit;

FIG. 3 is a detailed axial cut (upper half) through the intake region ofa gas turbine unit showing the combustion chamber and the turbine stage;

FIG. 4 shows the intake manifold of a gas turbine unit with a liquiddroplet injection device installed in the expansion joint according tothe present invention; and

FIG. 5 shows a liquid droplet injection device used according to thepresent invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

FIG. 1 shows a schematic view of a gas turbine unit. Intake air 10enters the compressor 1/2, which in this particular case is divided intoa first stage 1 operating at low-pressure and a second stage 2 operatingat high-pressure. The partially compressed intake air 11 exits the firststage 1 to be fed into the second, high-pressure stage 2. The partiallycompressed air 11 can be cooled prior to entering the high-pressurestage 2 by cooling means 21 in order to increase the power of the gasturbine unit (so-called inter-cooling). After full compression of theintake air, the compressed air 12 enters the combustion chamber 8. Thiscombustion chamber 8 is fuelled by a duct 9, and the hot air 13discharged from the combustion chamber 8 is fed into the turbine stage3. The exhaust air 14 discharged by the turbine 3 can then either bedischarged directly via a chimney to the surrounding or it can, asdisplayed in FIG. 1, be used in a heat recovery steam generator 15 togenerate steam for a steam turbine 4 and then be discharged via achimney 16. In the latter case water 17 is fed into a duct system in theheat recovery steam generator (steam drums, evaporators, economizersetc) for the generation of steam 18 to be fed into the steam turbine 4.The steam exiting the steam turbine 4 is then either discharged to thesurrounding or can be recycled by means of a condenser to re-enter theheat recovery steam generator 15.

FIG. 1 displays a so-called single shaft gas turbine, i.e. a gas turbinewhere compressor 1/2, gas turbine 3 as well as a generator 5 and a steamturbine 4 are mounted on one single shaft 6. Possibly, clutches allowthe de-coupling of some of these units from each other.

Also displayed in this schematic diagram are the cooling means forcooling components of the gas turbine unit. Usually, partially or fillycompressed cooling air 22 is branched off from either a stage of thecompressor within the compressor or at the end of the compressor. As thecompression process in the compressor results in a substantial heatingof the compressed air, this air has to be, for cooling purposes, cooleddown to the desired temperature levels. To this end, a cooling unit 24is provided in the cooling air ducts upstream of the locations where thecooling air 25 is to be injected. The cooling unit 24 can have variousdesigns, like for example conventional heat exchangers. In order toavoid the deposition and/or condensation of liquid (particularlycritical if heavy over-fogging is being applied upstream of thecompressor) in the cooling air ducts, a droplet separator 23 (e.g.centrifugal separator) may be provided in the ducts preferably upstreamof the cooling unit 24, but also at any other location where thedeposition of liquid shall be particularly prevented. The cooling aircan be used at various positions as displayed in FIG. 1, e.g. forcooling the combustion chamber 8, for cooling the turbine 3 as well as 4etc. If need be, the cooling air can be mixed with steam to enhance thecooling effect.

In order for the cooling system to work properly, the cooling system hasto be balanced such as to meet certain conditions. First the pressure inthe cooling ducts has to be larger than the pressure at the locationwhere the cooling air is to be injected to avoid flow-back of thecooling air into the cooling ducts. That is the reason why usuallycooling air is not just taken from the surrounding but rather branchedoff from the compressor where high pressure is already available (this,as mentioned above, with the inherent drawback that the air is notavailable at ambient temperature due to the compression process).Secondly the temperature of the cooling air may not exceed a certainlevel in order to allow effective cooling of the components where thecooling air is injected. Usually, the tolerances as concerns temperatureas well as pressure in these cooling systems are very low necessitatingsophisticated control mechanisms to stabilize and balance temperature aswell as pressure of the cooling air.

Usually the cooling air has a temperature of 300 to 600 degrees Celsiusand a pressure in the range of 10 to 30 bar at the point of dischargefrom the compressor. Typical are pairs of 400 degrees Celsius at 20 baror 500 degrees Celsius at 30 bar (to compare: the compressed air 12 fedinto the combustion chamber usually has a temperature of about 500degrees Celsius). The cooling air downstream of the cooling unit 24shall have a temperature in the range of 300 to 400 degrees Celsius,preferably temperatures in the range of 330 and 380 degrees Celsius. Thetolerances related to temperature are usually required to be less than+/−10 degrees Celsius to make sure the cooling system works properly.The pressure of the cooling air stream shall be in the range of 15 to 40bar, preferably in the range of 20 to 30 bar. Tolerances related topressure are usually required to be less than +/−0.5 bar. In order tofulfill these pressure and temperature requirements, the cooling unit 24is controlled depending on measurements of temperature and pressure atvarious locations (see below).

FIGS. 2 a and 2 b show the intake region of a gas turbine unit. Usuallyintake air 10 is aspired by a duct with large cross-section, which atthe entrance is provided with a filter 28 to avoid deleterious entranceof dust and other particles. Right downstream of said filter a firstevaporative air inlet cooling unit 29/33 is provided meaning any systemadding liquid to the air inlet mass flow, which substantially evaporatesbefore entering the compressor of the gas turbine unit, resulting in acooling effect and in an increase of the air intake mass flow into thegas turbine unit. This may for example be in the form of a liquidatomization spray system (‘fogging’ system) 29 in FIG. 2 a or in theform of a porous medium (evaporative cooler) 33 in FIG. 2 b. Therespective evaporative cooling system shall increase the humidity of theintake air as close to saturation as possible. Downstream of anevaporative cooler 33 a droplet catcher 34 preferably is provided toprevent excessively large droplets from entering the compressor of thegas turbine unit. It shall be mentioned that the injection spray device29 can also be used to inject more liquid than needed for saturating theintake air mass flow to achieve the same effect as with using theover-fogging means 32 described below. Subsequently, the cross-sectionof the intake duct 27 is reduced thereby increasing the flow velocity ofthe intake air 10. Usually downstream of this reduction of cross-sectionthere is a silencer installed in the intake duct. Downstream of thesilencer the intake duct 27 is connected with the intake manifold 26 bymeans of an expansion joint 31. The intake manifold 26 is fixedlyconnected with the gas turbine unit and is therefore subject tovibrations of the gas turbine. By contrast, the intake duct 27 isdirectly connected to the ground and shall be affected by the gasturbine's vibrations as little as possible, which is achieved byproviding an expansion joint 31 between the air intake manifold and theair intake duct. The location of the expansion joint 31 has been foundto be quite a favorable position for placing the liquid dropletinjection device 32 a, but is not the exclusive location for the liquiddroplet injection device (see below). Downstream of the liquid dropletinjection device 32 a, the intake manifold 26, which guides the intakeair into the compressor as smoothly as possible, is connected to theentrance of the compressor 1/2, which in this case is a compressorwithout inter-cooling. Alternative locations for the liquid dropletinjection device are e.g. at the compressor bellmouth as close to thecompressor entrance as possible (32 b) or behind the silencer (32 c).

Both elements 29 and 32 a/b/c preferably inject demineralized water inorder to avoid depositions in the gas turbine unit. Typically 1.0 to 3.0mass-% of water are added to the stream of intake air, and a waterpressure of >100 bar is used.

To visualize in more detail the conditions in the intake region of a gasturbine unit, FIG. 3 shows an axial cut through a gas turbine unit andin particular through its intake manifold 26. It can be seen that theliquid droplet injection device 32 a is arranged substantiallyperpendicular to the flow of intake air 10 at the interface between theintake duct 27 and the intake manifold 26. Preferably, the liquiddroplet injection device 32 a is positioned on the intake duct side ofthe expansion joint 31. This positioning proves to be advantageous as itshows minimum exposure to vibration, low pressure loss of the equipmentas well as even droplet distribution with small droplet sizes. Theintake air is over-saturated by the liquid droplet injection device 32a, is then deviated by a particular, flow adapted housing (the intakemanifold, FIG. 4) into the compressor 1/2, where the air is compressedin several steps but without inter-cooling. The temperature profile inthe casing of the gas turbine unit should be monitored to avoid damagesin case of irregularities.

FIG. 5 shows a nozzle rack as it can be used as the liquid dropletinjection device 32 a. The rack consists of a carrying frame 37 ontowhich liquid ducts 35 are mounted, typically with a variable spacing inthe range of approximately 20-30 cm. On these water ducts 35, liquidatomization nozzles 36 are mounted which allow a high flow capacity,good droplet cone and small droplet sizes thereby reducing bladingerosion rates. Usually 5-15 nozzles are mounted on one water duct. Asone can see from FIG. 5, the spacing of the nozzles as well as of thepipes is not necessarily regular. The positioning of the water ducts 35as well as of the liquid atomization nozzles 36 should be in a flowweighted manner to provide even droplet distribution. For example in thecase of an intake duct 27 and intake manifold 26 as displayed in FIG. 2a/b, where the intake air is diverted almost in a rectangular angle froma horizontal direction to a vertical direction in order to enter theintake manifold 26, the maximum of flow velocity in the region of theexpansion joint measured substantially perpendicular to the flow ofintake air is located closer to the outer side of the bend, with thevelocity maximum usually located within the third proximal to the outerside of the bend. Usually the nozzle density can be set substantiallyproportional to the velocity at a particular position in order toachieve homogeneous distribution of fine droplets across thecross-section of the intake air stream. The above applies in the casewhere all the nozzles are identically fed with water so that when thenozzles are distributed according to the flow of the air, more water isinjected in regions where there is a high flow velocity and where thereis a higher density of nozzles. It is generally easier to achievehomogeneously high droplet quality if all nozzles are fed identically.However, the same effect can be achieved with evenly distributed nozzlesand feeding nozzles, that are located in regions of high flow velocity,with more water. Also a combination of flow-adapted distribution of thenozzles with individual supply of the nozzles is possible and can beadvantageous if the flow conditions in the duct vary significantlydepending on the mode of operation of the gas turbine unit. The nozzlesmay be designed as binary nozzles fed with gas or quasi-gas and withliquid to provide good droplet quality.

As mentioned above, the over-fogging system can be combined withconventional evaporative air inlet cooling units as for exampledisplayed by means 29 in FIG. 2 a or 33 in FIG. 2 b. The conditions forstart-up of the over-fogging pumps are as follows: The gas turbine unitshould be at or near full load and the ambient wet bulb temperatureshould be above a certain value, typically above 0° Celsius. Ifconventional evaporative inlet air cooling equipment is installed, theinlet air cooling devices should be operating when the over-fogging isbeing activated if ambient conditions allow. Additionally, the full ornear full load operation of the gas turbine unit should have been activefor a certain warm-up period, which should be in the range of preferablyabout 30 minutes. The compressor inlet temperature has to be monitored.If this value drops below a certain level, usually given by about 0°Celsius, an automatic shutdown of the liquid injection system isnecessary. Also the over-fogging flow capacity has to be supervised todetect e.g. nozzle clogging, change in the nozzle flow capacity, leaks,differences between measured system water flow capacity etc., whichwould lead to uncontrolled water flows which should be avoided. Asmentioned above, also the quality of feed water should be supervised.Generally quality is monitored by measuring the conductivity whichshould not exceed a certain limit value. In addition, any freezing orblocking of the pipes system also should be monitored.

For plants with inlet cooling systems the following start-up schemeproves to be suitable:

1. Gas turbine unit is loaded up to or near to full load.

2. If the gas turbine unit is at or near full load operation,evaporative inlet cooling systems come into operation if the ambientconditions allow switching on of the inlet cooling system.

3. After operating at or near full load for at least approximately 30minutes, the over-fogging system can come into operation.

In case a plant is not equipped with an evaporative inlet coolingsystems, the above step 2 can be skipped.

For shutdown, the above procedure can be carried out in the reverseorder.

LIST OF REFERENCE NUMERALS

1 first stage of compressor (low-pressure)

2 second stage of compressor (high-pressure)

3 turbine

4 steam turbine

5 generator

6 common shaft

7 clutch

8 combustion chamber

9 fuel duct, fuel

10 intake air

11 partially compressed intake air

12 compressed air

13 hot combustion air

14 exhaust air

15 heat recovery steam generator

16 chimney

17 duct to the heat recovery steam generator

18 duct from the heat recovery steam generator (steam)

19 outlet of the steam turbine

20 cooling/fogging of intake air

21 cooling of partially compressed air

22 cooling air duct, compressed cooling air

23 droplet separator

24 cooling unit

25 cooled cooling air

26 intake manifold

27 intake duct

28 filter

29 fogging liquid droplet injection device

31 expansion joint

32 a/b/c over-fogging liquid droplet injection device

33 evaporative cooler

34 droplet catcher

35 water duct

36 atomisation spray nozzle

37 carrying frame

38 fuel control valve

39 control signal line

20 a valve

40 feed forward signal

1. A process for changing shaft power production from a gas turbine unitthat comprises a compressor for compressing a stream of intake airsupplied thereto and discharging compressed air, a combustion chamber inwhich fuel is combusted with the compressed air discharged from saidcompressor, and a turbine driven by hot combustion air discharged fromsaid combustion chamber, the process comprising: operating saidcompressor with a pressure ratio larger than 15 bar; injecting liquiddroplets into the stream of intake air using at least one liquid dropletinjection device disposed on an upstream side of said compressor toincrease shaft power generated by the gas turbine unit; controlling theat least one liquid droplet injection device so that responsive to adesired increase of shaft power output, the at least one liquid dropletinjection device delivers the liquid droplets to reach a discrete rateof mass flow within 60 seconds; and adjusting the fuel mass flow with afuel control valve in order to maintain firing temperatures of the gasturbine unit, wherein the at least one liquid droplet injection deviceis operable with an on/off-control signal, and wherein the fuel controlvalve is controllable as a function of liquid droplet injection using asingle feed forward signal synchronized to the on/off-control signal. 2.The process of claim 1, wherein liquid mass flow is substantiallyinjected across the entire cross-section of an intake air guide.
 3. Theprocess of claim 1, further comprising cooling components of the gasturbine unit with a cooling system using at least partially compressedair discharged from the compressor, wherein the cooling system comprisesa cooling unit that is controlled depending on quality with respect totemperature and pressure of air cooled thereby.
 4. The process of claim1, wherein between 0.5 mass % and 5 mass % of liquid are injected intothe intake air to achieve an increase of shaft power of the gas turbineunit of up to 10%.
 5. The process of claim 1, wherein the amount ofliquid injected into the intake air is decreased by between 0.5 mass %and 5 mass % of liquid to achieve a reduction of shaft power of the gasturbine unit of up to 10%.
 6. The process of claim 1, wherein between 1mass % and 3 mass % of liquid are injected into the intake air toachieve an increase of shaft power of the gas turbine unit of up to 10%.7. The process of claim 1, wherein the amount of liquid injected intothe intake air is decreased by between 1 mass % and 3 mass % of liquidto achieve a reduction of shaft power of the gas turbine unit of up to10%.
 8. The process of claim 1, wherein water is injected at pressure ashigh as 250 bar water pressure, and the pressure is achieved within 1second and 60 seconds.
 9. The process of claim 8, wherein the pressureis achieved within 10 seconds and 30 seconds.
 10. The process of claim1, wherein water is injected at pressure between 100 bar and 180 barwater pressure, and the pressure is achieved within 1 second and 60seconds.
 11. The process of claim 10, wherein the pressure is achievedwithin 10 seconds and 30 seconds.
 12. The process of claim 1, whereinwater is injected at pressure about 140 bar water pressure, and thepressure is achieved within 1 second and 60 seconds.
 13. The process ofclaim 12, wherein the pressure is achieved within 10 seconds and 30seconds.
 14. The process of claim 1, wherein the power output of the gasturbine unit available on a generator coupled to the gas turbine unit israpidly increased or decreased using an addition or reduction of liquidmass flow.
 15. The process of claim 14, wherein the rapid increase ordecrease is generated in response to a fast increase or decrease inpower demand of an electricity grid coupled to the gas turbine unit, andby an addition or reduction of water a surge margin of the compressor isincreased or decreased by cooling a compressor blade section.
 16. Theprocess of claim 15, wherein the rapid increase or decrease is generatedin response to a drop or rise of frequency of the electricity grid. 17.The process of claim 16, wherein the drop or rise of the frequency ofthe electricity grid results in a reduction or augmentation of shaftspeed of the gas turbine unit.
 18. The process of claim 1, wherein theliquid droplets are injected after a delay of between 15 minutes and 45minutes after starting up the gas turbine to full load.
 19. The processof claim 18, wherein the liquid droplets are injected after a delay ofabout 30 minutes after starting up the gas turbine to full load.
 20. Theprocess of claim 18, wherein additional cooling systems are switched onafter a delay of between 15 minutes and 45 minutes after starting up thegas turbine to full load.
 21. The process of claim 1, wherein the singlefeed forward signal and the on/off-control signal are synchronized butdisplaced relative to each other sufficient to account forhysteresis-effects of the gas turbine unit.